Zhang, Yandong (Missouri University of Science and Technology) | Wei, Mingzhen (Missouri University of Science and Technology) | Bai, Baojun (Missouri University of Science and Technology) | Yang, Hongbin (China University of Petroleum) | Kang, Wanli (China University of Petroleum)
Enhanced oil recovery (EOR) processes are regarded as important methods to recover remaining oil after primary and secondary recovery. It is important to select the most appropriate EOR process among the possible techniques for a candidate reservoir. Therefore, EOR screening criteria have been constructed using available EOR data sets and serve as the first step to compare the suitability of each EOR method for a particular reservoir. Most screening criteria for polymer flooding are based on data sets from EOR surveys published biannually by the Oil & Gas Journal. These surveys missed significant polymer flooding parameters such as formation water salinity and hardness, polymer types and molecular weight, polymer concentration, reservoir heterogeneity, and so on. All of these topics are covered in this paper with data from relevant literature and records provided by oil companies in China.
Polymer flooding has been widely applied in China for over 20 years and a large number of pilot and field projects have been conducted. These projects include important information to quantify the development of polymer flooding as an EOR method. Nevertheless, most of them have been published in Chinese, and are not accessible to the global research community due to the language barrier. This paper represents an effort to collect all relevant information of polymer flooding from available Chinese publications and reports from all of the major oil companies in China. The primary objectives of this survey is to reveal EOR advances, to trace the development of the polymer flooding EOR methodology in China, and to benefit EOR worldwide.
This project collected information on 55 polymer flooding projects after reviewing nearly 200 publications in Chinese, including 31 pilot projects and 24 field projects from 1991 to 2014. A data set was constructed by collecting all relevant information for polymer flooding. Statistical analyses and graphical methods were used to analyze the whole data set. Box plots combined with violin plots were used to show the distribution and the range of each parameter. By defining and calculating lower and upper limits in box plots, special projects were identified and explained. Scatter plots, which show multiple parameters in one plot, were used to identify significant relationships among different parameters, especially for dependent parameters. This method overcomes some disadvantages of the range method, which is traditionally used for EOR screening. For example, using polymers with high concentration in low salinity reservoirs can lead to higher incremental oil recovery than in high salinity ones, and lower permeability usually correlates with the use of polymers with lower molecular weight. However, the traditional range method cannot show this relationship. Finally, comprehensive screening criteria for polymer flooding were updated based on information revealed in the field application projects.
This paper addresses two questions for polymer flooding. First, what polymer solution viscosity should be injected? A base-case reservoir-engineering method is present for making that decision, which focuses on waterflood mobility ratios and the permeability contrast in the reservoir. However, some current field applications use injected polymer viscosities that deviate substantially from this methodology. At one end of the range, Canadian projects inject only 30-cp polymer solutions to displace 1000-3000-cp oil. Logic given to support this choice include (1) the mobility ratio in an unfavorable displacement is not as bad as indicated by the endpoint mobility ratio, (2) economics limit use of higher polymer concentrations, (3) some improvement in mobility ratio is better than a straight waterflood, (4) a belief that the polymer will provide a substantial residual resistance factor (permeability reduction), and (5) injectivity limits the allowable viscosity of the injected fluid. At the other end of the range, a project in Daqing, China, injected 150-300-cp polymer solutions to displace 10-cp oil. The primary reason given for this choice was a belief that high molecular weight viscoelastic HPAM polymers can reduce the residual oil saturation below that expected for a waterflood or for less viscous polymer floods. This paper will examine the validity of each of these beliefs.
The second question is: when should polymer injection be stopped or reduced? For existing polymer floods, this question is particularly relevant in the current low oil-price environment. Should these projects be switched to water injection immediately? Should the polymer concentration be reduced or graded? Should the polymer concentration stay the same but reduce the injection rate? These questions are discussed.
It is generally assumed that while the presence of foam reduces the mobility of the gas phase, it does not alter the mobility of the liquid phase. Here, the effect of surfactant type and concentration on the behavior of nitrogen foam flow in porous media is investigated by simultaneous injection of gas and surfactant into Bentheimer sandstone cores. Different surfactant types, viz., anionic alpha-olefin-sulfonate (AOS) and zwitterionic Betaine with different surfactant concentrations from critical-micelle-concentration (CMC) to higher concentration are used in this study. The foam strength is quantified by measuring the pressure drop in different sections of the core. The liquid saturation is measured by analyzing the X-ray images obtained in a medical CT-scanner.
It is shown that the connate water saturation is reduced by increasing the surfactant concentration, and therefore the relative permeability relation for the aqueous phase should be modified when fitting the data to the foam models. It is observed that it is not possible to fit one monotonic liquid relative permeability curve to all the data points, obtained with different surfactant type and concentration in one rock type. Moreover, increasing AOS concentration above a certain value does not have a significant effect on the mobility reduction of the gas phase; however it modifies the liquid relative permeability. These results indicate that the water relative permeability measured in absence of surfactant should not be used to model the flow of foam in porous media, as it can lead to erroneous calculations of the liquid saturation.
Zhu, Youyi (State Key Laboratory of Enhanced Oil Recovery, Research Institute of Petroleum Exploration and Development, CNPC) | Fan, Jian (State Key Laboratory of Enhanced Oil Recovery, Research Institute of Petroleum Exploration and Development, CNPC) | Liu, Xiaoxia (State Key Laboratory of Enhanced Oil Recovery, Research Institute of Petroleum Exploration and Development, CNPC) | Li, Jianguo (State Key Laboratory of Enhanced Oil Recovery, Research Institute of Petroleum Exploration and Development, CNPC)
Chemical flooding technology is one of the effective enhanced oil recovery (EOR) methods for high water cut sandstone reservoirs with either medium and/or high permeability. Because of the small pore throat radius in the pore medium of low permeability reservoir, high molecular weight polymers cannot be injected in the low permeability reservoir. Therefore, many traditional chemical floodings (such as polymer flooding, alkali-surfactant-polymer (ASP) flooding and surfactant-polymer (SP) flooding) cannot be effectively applied in this case. Small-molecule viscoelastic surfactant (VES) has special rheological properties in porous medium. It showed both viscosified function and reduction of oil/water interfacial tension (IFT) performances under certain conditions, thereby providing the possibility of IOR/EOR potential application in low permeability reservoirs.
Most of reservoirs in Jilin Oilfield belong to low permeability reservoirs with permeability of around 50 mD in average. The recovery percent of reserves in Fuyu was only 23% by water flooding with water cut as high as 93%. A candidate EOR technique with chemical flooding has been proposed. Studies on VES flooding EOR methods targeting this reservoir condition were conducted. The rheological property, IFT property, viscosifying ability of VES and core flooding experiments of VES system were studied.
From VES screening experiment, a type of zwitterionic betaine surfactant with long carbon chain was selected. It showed viscosifying behavior, shear thinning property and low IFT performances at reservoir conditions. VES of EAB solutions showed a good viscosifying action at low surfactant concentration. Moreover, based on its shear thinning property under the wide shear rate conditions, VES exhibited a good injectivity performance. IFT between crude oil and formation water with EAB was 10-3-10-2 mN/m order of magnitudes. The results could be obtained at the concentration ranges of surfactants from 0.1wt% to 0.4wt%. Ultralow IFT (10-3 mN/m order of magnitudes) could be obtained in the presence of co-surfactants or alkalis (such as sodium carbonate). Core flooding experiments of VES flooding showed that the incremental oil recovery factors could reach up to 13%-17% over conventional water flooding at Fuyu reservoir conditions. Test results indicated that VES flooding might become a promise alternative EOR method for low permeability reservoir after water flooding.
In contrast to the complexity of ASP/SP combination system, VES flooding could avoid chromatographic effects in the reservoir based on their simple formula (single surfactant compound). This new chemical flooding technique might have a great potential for EOR application in the low permeability reservoirs.
With the synergy of horizontal drilling and hydraulic fracturing techniques, commercial production of Unconventional Liquid Reservoirs (ULR) has been successfully demonstrated. Due to the low recovery factor of these reservoirs, it is inevitable that Enhanced Oil Recovery (EOR) will ensue. Experimental results have shown promising oil recovery potential using CO2. This study investigates oil production mechanisms from the matrix into the fracture by simulating two laboratory experiments as well as several field-scale studies, and evaluates the potential of using CO2 huff-n-puff process to enhance the oil recovery in ULR with nano-Darcy range matrix permeability in complex natural fracture networks.
This study fully explores mechanisms contributing to the oil recovery with numerical modeling of experimental work, and provides a systematic investigation of the effects of various parameters on oil recovery. The core scale modeling utilizes two methods of determining properties that are used to construct 3D heterogeneous models. The findings are then upscaled to the field scale where both simple and complex fractures in a single stage are modeled. The effects of reservoir properties and operational parameters on oil recovery are then investigated. In addition, this study is the first to present simulation results of CO2 huff-n-puff using complex fracture networks which are generated from microseismic-constraint stochastic models.
Diffusion is proven to be the dominant oil recovery mechanism at the laboratory scale. However, the field-scale reservoir simulation indicates diffusion is negligible compared to the well-known mechanisms accompanying multi-contact miscibility. This includes swelling, viscosity reduction, and gas expansion in the matrix. Overall, the CO2 huff-n-puff process was found to be beneficial in both models in terms of enhancing the ultimate oil recovery in ULR.
Yao, Chuanjin (China University of Petroleum) | Xu, Xiaohong (China University of Petroleum) | Wang, Dan (China University of Petroleum) | Lei, Guanglun (China University of Petroleum) | Xue, Shifeng (China University of Petroleum) | Hou, Jian (China University of Petroleum) | Cathles, Lawrence M. (Cornell University) | Steenhuis, Tammo S. (Cornell University)
Micron-size polyacrylamide elastic microspheres (MPEMs) are a smart sweep improvement and profile modification agent, which can be prepared controllably on the ground through inverse suspension polymerization using acrylamide crosslinked with an organic crosslinker. MPEMs can tolerate high temperature of 90 °C, high salinity of 20000 mg/L and wide pH value range of 4.0–10.3. MPEMs suspension almost has no corrosion effect on the injection pipeline and equipment. MPEMs can suspend in produced water easily and be pumped into formation at any rate. More importantly, MPEMs can reach the designed size after hydration swelling in oil formation and a reliable blockage can be formed; MPEMs can deform elastically and move forward step by step to realize a moveable sweep improvement and profile modification process in reservoirs. The pore-scale visualization experiment shows that there are four migration patterns for MPEMs transport in porous media and they are smooth passing, elastic plugging, bridge plugging and complete plugging. MPEMs can deform depending on their elasticity and pass through these pore-throats. Parallel-sandpack physical modeling experiment under the simulated reservoir conditions shows that MPEMs mainly enter into and plug high permeability layer whose permeability is reduced from 3.642 µm2 to 0.546 µm2, and almost do not clog low-permeability layer whose permeability is reduced from 0.534 µm2 to 0.512 µm2. Field application results of MPEMs treatment in a serious heterogeneous, high temperature and high salinity reservoir show that MPEMs can effectively improve swept volume and displacement efficiency. Because of the excellent properties, MPEMs treatment will become a cost-effective method for sweep improvement and profile modification to serious heterogeneous, high temperature and high salinity reservoirs with fractures and channels.
Jahanbakhsh, A. (Centre for Enhanced Oil Recovery and CO2 Solutions, Institute of Petroleum Engineering, Heriot-Watt University) | Sohrabi, M. (Centre for Enhanced Oil Recovery and CO2 Solutions, Institute of Petroleum Engineering, Heriot-Watt University) | Fatemi, S. M. (Centre for Enhanced Oil Recovery and CO2 Solutions, Institute of Petroleum Engineering, Heriot-Watt University) | Shahverdi, H. (Centre for Enhanced Oil Recovery and CO2 Solutions, Institute of Petroleum Engineering, Heriot-Watt University)
Gas/oil interfacial tension (IFT) is one of the most important parameters that impact the performance of gas injection in an oil reservoir. The choice or design of the composition of the gas injected for EOR is usually affected by the gas/oil IFT. In conventional reservoir simulation, IFT does not explicitly appear in the equations of flow and therefore its effect must be captured by the shape and values of relative permeability curves. A few studies have been previously reported for IFT effect on two-phase flow but very little have been done to investigate gas/oil IFT effect under three-phase flow conditions. The objective of this study is, firstly, to investigate the impact of gas/oil IFT reduction on two- and three-phase relative permeabilities using coreflood experiments. Secondly, to investigate the effect of changing gas/oil IFT value (immiscible and near-miscible) on the performance of WAG injections and residual oil saturation reduction at laboratory scale.
Two- and three-phase (WAG) coreflood experiments have been performed on water-wet and mixed-wet cores at three different gas/oil IFT conditions. These experiments were conducted on Clashach sandstone cores with a permeability of 65 and 1000 mD. The two- and three-phase relative permeabilities were estimated from the results of the coreflood experiments using our in-house software (3RPSim) and were compared with each other on the basis of their gas/oil IFT values. Moreover, the impact of gas/oil IFT reduction on the performance of gas and WAG injection and in particular on the reduction of residual oil saturation was investigated. The results of our studies were also compared with the existing literature on the laboratory investigation of WAG injection.
The results show that in two-phase gas/oil systems, the relative permeability of non-wetting phase is more affected by a reduction in the gas/oil IFT compared of the relative permeability of the wetting phase. Comparing the curvature of the gas and oil relative permeability curves shows that although the curvature decreases by a reduction in gas/oil IFT but it is still far away from straight line even at ultra-low IFT values. In three-phase flow system, reduction of gas/oil IFT affects the relative permeabilities of all the three phases (gas, oil and water).
The results show that at high gas/oil IFT or immiscible WAG injection, the most reduction in residual oil saturation is achieved in the first injection cycle and further WAG cycles do not result in a significant additional reduction in oil saturation. On the contrary, at low gas/oil IFT or near-miscible WAG injection, the residual oil saturation keeps decreasing as the number of WAG cycles increases. Moreover, the reduction in residual oil saturation was more effective when the immiscible WAG experiments started with gas injection (secondary WAG).
Davidson, Andrew (Chevron Energy Technology Company) | Nizamidin, Nabijan (Chevron Energy Technology Company) | Alexis, Dennis (Chevron Energy Technology Company) | Kim, Do Hoon (Chevron Energy Technology Company) | Unomah, Michael (Chevron Energy Technology Company) | Malik, Taimur (Chevron Energy Technology Company) | Dwarakanath, Varadarajan
Low microemulsion viscosity is critical for the success of chemical EOR. Typical microemulsion viscosities are measured using a rheometer and are considered to be static measurements. Given that microemulsions have a propensity to show non-Newtonian behavior, static viscosity measurements are not scalable to dynamic viscosities observed in cores and hence difficult to scale-up to field designs using simulations. We present a technique to measure dynamic microemulsion viscosity using a modified two-phase steady state relative permeability setup. Such dynamic viscosities provide a more practical feel for microemulsion viscosity under reservoir conditions in the pores and allow for selection of low microemulsion viscosity formulations. A two-phase steady state relative permeability setup was used with continuous co-injection of oil and surfactant. A glass filled sand pack was used as a surrogate core and the injection fluids were allowed to equilibrate into the appropriate phases as determined by the phase behavior. For the rapidly equilibrating and low viscosity Winsor Type III formulations three phases are clearly observed in the sand packs. Using the phase cuts in the sand pack/effluent and the known oil and water viscosities, we can estimate the microemulsion viscosity. Both low and high viscosity formulations were tested in corefloods and oil recovery measured to illustrate the importance of low viscosity microemulsions for oil recovery. As expected, the low viscosity microemulsions correlated with higher oil recovery. In addition, the equilibration times to reach Winsor Type III microemulsions were also linked to better oil recovery. For the well behaved formulations that equilibrated in less than 2 days the static microemulsion viscosity correlated well with the dynamic viscosity. The modified steady state relative permeability setup can accurately estimate microemulsion viscosity and allow for better screening of surfactant formulations identified for field flooding. The dynamic microemulsion viscosities can also provide inputs for numerical simulation and better predict microemulsion behavior in the subsurface during field surfactant floods.
Wang, Haitao (Petroleum Exploration & Production Research Institute, Sinopec) | Lun, Zengmin (Petroleum Exploration & Production Research Institute, Sinopec) | Lv, Chengyuan (Petroleum Exploration & Production Research Institute, Sinopec) | Lang, Dongjiang (Petroleum Exploration & Production Research Institute, Sinopec) | Pan, Weiyi (Petroleum Exploration & Production Research Institute, Sinopec) | Luo, Ming (Petroleum Exploration & Production Research Institute, Sinopec) | Wang, Rui (Petroleum Exploration & Production Research Institute, Sinopec) | Chen, Shaohua (Petroleum Exploration & Production Research Institute, Sinopec)
Nuclear magnetic resonance (NMR) was used to investigate the exposure between CO2 and matrix with permeability of 0.218 mD at 40 °C and 12 MPa. Before NMR experiment, the core was saturated with oil. To investigate the effects of exposure time on EOR, the saturated core was exposed to CO2 and T2 test was continuously performed with NMR system until the obtained T2 spectrum was unchanged. After the first exposure, CO2 and matrix reached equilibrium state. The second exposure started when CO2 injection was under a constant pressure of 12 MPa and at a constant rate to keep fresh CO2 in system. The procedure of T2 test was unchanged. The third and fourth exposures were conducted in sequence. The results showed that (1) Oil in all pores can mobilize as exposure time increases. (2) The recovery is 46.6% for oil in pores with the diameter of pore larger than 1 µm, this result is higher than the recovery (12.8%) for oil in pores with the diameter of pore smaller than 1 µm. (3) Recovery can be divided into two stages according to the exposure time: a fast-growing stage and a slow-growing stage. (4) Initially, the oil exists in pores with maximum radius of 21 µm in the originally saturated core. After CO2 injection, oil flows to pores with radius greater than 21 µm, suggesting that oil in tight matrix "diffuses" to the surface of core with exposure between CO2 and matrix. (5) The final recoveries of 1st, 2nd, 3rd, 4th exposure experiments are 23.7%, 7.2%, 2.6% and 1.5%, respectively.
MEOR (microbial enhanced oil recovery) is known as one of the emerging low-cost EOR technologies, which uses in-situ microorganisms living in the oil field. Some of the most promising microbial-induced mechanisms include production of extracellular polymeric sugars (EPS), biofilms as well as selective plugging caused by cell growth. However, there is limited data available concerning the way microbes and biofilms behave in contact to surfaces in porous media in the context of MEOR. The aim of this work was to investigate bacterial growth and biofilm production in the framework of an ongoing MEOR project conducted by Wintershall and BASF. We used various approaches to investigate cell behavior of a halophilic bacterial community derived from a Wintershall oil field. Bacterial growth was conducted in both batch cultures and under dynamic conditions. To visualize cell adhesion and also exopolymers occuring in biofilms we used specific fluorescent dyes. During incubation of the microbes over several weeks we could visualize different types of EPS under the microscope. This observation fits perfectly to a concurrent viscosity increase of the surrounding media. Modelling approaches were applied to estimate the potential contribution of these effects on additional oil recovery. The observations including cell clumping, sorption and polymer production were geometrically quantified and the effect of the modifications on permeability profile and resulting flow characteristics was numerically investigated with fluid dynamic simulations of the petrophysical changes. The potential implications of the observed changes on EOR capability by conformance control and wettability modification were further estimated with analytical approaches. With the developed methods for visualization and modelling of the microbes and biofilms in both batch and dynamic conditions, we are able to monitor the clumping and sorption behavior of the cells, which will help to interprete data obtained during an upcoming MEOR field trial.